An oil and gas company which sells petroleum products typically deals with many producers and customers and uses diverse assets (such as wells, processing facilities, and pipelines) in wide-spread geographical locations. For example, many steps are involved in the production, gathering, processing, and sale of natural gas and its derivative products. An integrated natural gas company may have its own exploration and production operations. The integrated natural gas company may also deal with a number of independent producers, each with different contractual terms concerning the purchase and production of natural gas.
FIG. 1 shows a typical hydrocarbon gathering system 10. Producing wells 12 may be owned and operated by the gathering company or by third party producers. These wells 12 are connected by gathering lines 14 that gather produced gas and transport the gas to, for example, gas processing plants 16. At each well 12, natural gas measurement equipment 18 is installed to measure the pressure and volume of natural gas that is produced. Measurement of the flow volume and natural gas composition at each well is important because the natural gas gatherer must know both the quantity and composition of natural gas that has been produced and that is being transported in the gathering system 10.
Natural gas that has been gathered from producing wells 12 is typically transported to a gas processing plant 16 via gathering lines 14. If the gathering line 14 is of a low pressure type, there may be a compression station 20 integrally located with the gathering line 14 to compress the natural gas. At the gas processing plant 16, the gas is treated to produce pipeline quality natural gas and marketable natural gas liquid (NGL) derivatives. The gas is finally sent to a pipeline 22 where it may be distributed to customers, third parties, or storage facilities. NGLs are typically transported to storage tanks 24 where they may be delivered 26 to customers via truck. However, if sufficiently large quantities of NGLs are produced by a gas processing plant 16, the NGLs may be delivered directly to customers via a pipeline.
Natural gas, when produced from the earth, may have a widely varying composition depending on the field, the formation, or the reservoir from which it is produced. The principal constituents of natural gas are methane and ethane, but most gases contain varying amounts of higher carbon content components, such as propane, butanes, and other hydrocarbons. Natural gas may also contain water, hydrogen sulfide, carbon dioxide, nitrogen, helium, or other components that may be dilutents and/or contaminants. Natural gas is typically processed into two parts: a light gas component and a heavier gas-derivative liquid (e.g., natural gas liquid, or NGL) component.
The separation of the two parts is typically performed in gas processing plants (GPP) with either absorption or cryogenic processes. The light gas component typically comprises mostly methane, while the liquid derivatives typically comprise the remaining ethane, propane, butane, isobutane, and natural gasoline, among other liquids. These natural gas liquids (NGLs) are separated from the light gas component because NGLs have separate commercial value and to make the natural gas component merchantable.
Natural gas gathering companies must closely monitor all aspects of natural gas production, gathering, processing, and delivery. Many monitoring functions are now performed with electronic devices, such as electronic flow meters (EFMs), remote terminal units (RTUs), and programmable logic controller (PLCs). For example, EFMs monitor pressure and flow volume at each well and at inlets and outlets of compression stations and gas processing plants. EFMs, RTUs, and PLCs may be used to monitor compressor performance (e.g., compressor rpm, compressor inlet pressure, and compressor outlet pressure, among other values) at compression stations. The data collected by the EFMs, RTUs, PLCs, and other remote electronic devices may be gathered and stored by computer based systems. The computer based systems may be referred to as supervisory control and data acquisition (SCADA) systems. SCADA systems have many uses, including the management of energy production operations.
Other traditionally manual tasks are now performed electronically. For example, monitoring of cathodic protection elements on gas pipelines may be monitored with electronic, remotely accessible devices. Storage tanks for natural gas products may also be monitored electronically. As a result, many processes traditionally performed by field personnel have been converted to electronic methods to increase accuracy and reduce the amount of labor required to continuously monitor production and storage facilities.
Throughout natural gas gathering operations, it is important to have accurate metering of the gas volume and pressure and to have an accurate analysis of gas components. EFMs located at various positions along the pipelines and at production wells provide most of the volume and pressure data. These meters need to be calibrated frequently to make sure that they accurately measure pressure and flow volume. The testing process is laborious because field technicians must physically go to the meters, which are typically widely dispersed geographically, to perform the testing. In addition, gas purchase contracts generally provide the producer with the option to have a witness attend the meter testing so that test results may be verified. In some situations, contractual terms may dictate that these tests be performed based on the volume of hydrocarbon delivered over a selected period of time. Therefore, it can be difficult to predict the time when the EFM testing must be performed.
Proper gas sample analysis is also important for accurate measurement during gathering, processing, and sale of natural gas products. As mentioned previously, natural gas produced from different reservoirs typically has different chemical compositions. While EFMs measure pressure and volume of natural gas flow, it is necessary to measure natural gas composition so that the energy content of the gathered natural gas may be determined. “Energy content” typically refers to the amount of heat energy that is produced during combustion of the natural gas. Some natural gas compositions, for example those containing at least a fractional percentage of heavier hydrocarbons (such as ethane), produce more energy when burned as fuel as compared to combustion of pure methane. Energy content is important to gathering companies because natural gas sales are typically based upon energy in BTU/scf (British Thermal Units per standard cubic foot). Knowledge of natural gas composition enables gathering companies to accurately convert flow volume to BTU content. Contractual terms for the purchase of pipeline quality gas often set limits as to the energy content and component content. Therefore, the gathering company typically must send technicians to the field to take samples and then analyze the samples in the laboratories to determine the composition of the natural gas produced from each well. Further, NGLs produced and stripped by gas processing plants may be allocated to producing wells.
The overall production and delivery of natural gas must be balanced. That is, the amounts of natural gas and NGLs gathered from all producing wells tied to a gathering system must be balanced with the amounts of gas and NGLs delivered to customers and storage facilities. The balance procedure is traditionally performed periodically (e.g., monthly) when all of the volume, pressure, energy, and composition data are collected. If there is any imbalance, it is often difficult to determine the exact source because the absence of a centralized near real time database and the inherent latency in the collection of all required data.
While the collection of data from EFMs, RTUs, and PLCs has been automated through the use of SCADA systems, prior art automation approaches have achieved integrated operations only for selected segments of the process of gathering, processing, and distribution rather than for the entire production, gathering, processing, and final sale of natural gas. Traditionally, problems in each segment of natural gas gathering and distribution (e.g., physical testing and metering, system balancing, and natural gas composition analysis) have been addressed independently. The independent approach results in fragmented operations where operating data and information is not efficiently shared between segments. Furthermore, multiple entries of continuously changing data can create accounting errors and inconsistencies between segments.
There is, therefore, a need for a system that coordinates the many tasks that are included in the processes surrounding the production, gathering, processing, and sale of natural gas and other hydrocarbons. The system should combine many of the tasks and should eliminate errors resulting from the fragmented management and production processes.